As is well known, shutting in a drilling and completions well, e.g., an oil well, a gas well, a water well, a disposal well, an injection well or the like, also referred to herein as a well, is required following an undesired influx of formation fluids into the wellbore from the surrounding formation during drilling operations. This undesired influx of formation fluids is also referred to as a “kick.” After shutting in the well, additional formation fluid continues to flow into the well. Conventionally drillers, also referred to herein interchangeably as rig personnel, users and operators, must keep the well shut in following a kick, i.e., after “taking a kick,” until they have obtained stabilized shut in casing pressure (SICP) and shut in drill pipe pressure (SIDPP) readings. As the additional fluid flows into the well, wellbore fluid is compressed and the SICP increases until the influx stops when bottom hole pressure (BHP) equals the surrounding formation pressure. As the influx volume increases, the maximum pressure exerted at the well shoe during circulation increases. Especially when the formation surrounding the well has low permeability, there is a slow pressure build up and corresponding long pressure build up curve. Common industry well control practices require that a well remain shut in for many hours in a static condition to allow these pressures to stabilize. In some cases, this long wait period may still not generate a true stabilized SICP and SIDPP. The very gradual increase in SICP can result in choosing an inaccurate stabilized SICP and SIDPP. This can lead to circulating the well in an underbalanced state, resulting in an increase in influx size and therefore an increase in environmental and safety risks involved in a well control event. The inaccurate choices for SICP will lead to attempts by rig personnel to kill the well with improper density drilling mud, also referred to as kill weight mud (KWM), which results in additional nonproductive time. Kill weight mud is a drilling mud, also referred to as drilling fluid, having sufficient density to prevent fluids from flowing into the wellbore.
FIG. 1 is a simplified cross-sectional view illustrating a subsea well according to the prior art. A surface mud pump 2 is used to pump drilling mud into a drill pipe 6, downhole and back to the surface through a well annulus 8 and to a choke line 15. Choke line 15 includes a valve 14 for controlling flow of drilling mud there through. A number of pressure sensors are typically provided, such as drill pipe pressure sensor 4, kill line pressure sensor 16 in kill line 20, downhole pressure sensor 10 (in the downhole tools located in the wellbore), wellhead pressure sensor 18 and choke line pressure sensor 12. A pressure sensor can be located on a stand pipe manifold (not shown) for stand pipe pressure. The choke and kill pressure sensors can be located on a choke and kill high pressure manifold (not shown). FIG. 1 illustrates a subsea well, but this could also represent a land well.
There exists a need for a method of determining an accurate stabilized shut in casing pressure after shutting in a well after taking a kick to increase the safety and efficiency of the well kill.